Crude petroleum liquid, commonly known as ‘crude oil’, contains varying amounts (1-25% w/v) of paraffin waxes as well as microcrystalline waxes. The waxes are soluble in crude oil at the reservoir temperature and pressure, but crystallize out of solution at lower temperatures/pressures prevailing at the shallower parts of wellbore and the surface production facilities. Therefore, formation of waxy deposits in the inner wall of the production tubing and flowlines is a frequently encountered problem that the oil companies have to deal with. The methods for dealing with the wax deposition problem in the production tubing include scraping with wireline-run tools, thermal or chemical treatments, or a combination of these. Without such measures, there is a likehood of well tubing getting plugged by the waxy deposit, resulting in enormous production loss.
Oilwells are often completed with packers for several reasons such as: stabilization of heading-and-surging type of flow, for isolating different zones, as a part of gas lift completion (an artificial lift method that is resorted to when the oilwell stops flowing on its own), etc. The most common reason for installing packer is to isolate the annular space (formed by the casing inner wall and the production tubing outer wall) that serves as a volume chamber for the lift gas in a gas-lift completion. An oilwell may be completed with gas lift valves and packer much before it stops flowing on its own, in order to avoid a work over later on.
An oilwell with packer often has aqueous fluid (water-based well completion fluid) trapped in the annular space. This water undergoes repeated evaporation in the lower part of the well, where the temperature is higher, and condensation in the upper part of the well where the temperature is lower. This is known as wellbore ‘refluxing’. Much of the heat for the evaporation comes from the flowing crude oil. Anomalously low temperatures, therefore, are recorded in wells completed with packers. Consequently, the wax deposition problem in such wells is also very severe. This is depicted in the FIGS. 1-3.
The severity of the problem can be gauged by comparing the well servicing time in flowing wells without packer (1-2 hours) with that required for a well with packer (4-6 hours). Thus, the oil company operators have to devote considerable amount of resources on an ongoing basis (e.g. dedicated wireline unit and crew) for the remediation of wax deposition in oilwells with packers. Occasionally, undesirable incidents such as parting of wireline and loss of scraping tool in the well occur, further aggravating the potential for production loss.
Conventional methods for remediation of severe wax deposition are given here;
One of the most frequently used methods for remediation of severe wax deposition is use of mechanical tools such as wireline-run cutter. This method is also known as scraping. This method has many limitations—the crew has to move to the well location, rig up the cutting tool equipment and carry out the wax cutting operation for several hours. Carrying out such an operation day-after-day is not only resource intensive, but also cumbersome, monotonous and prone to errors by the crew. On account of such errors, ‘fishing’ may occur, i.e., the scraping tool may part from the wireline and fall into the wellbore. This creates restriction in the well and also may restrict production.
Another method for remediation of severe wax deposition makes use of chemicals to inhibit the formation, growth and adhesion of wax crystals. This involves high cost, since the injection has to be done on a continuous basis. Moreover, a workover operation is required for the installation of mandrel/valve through which the chemical injection can be carried out. Such a workover is not only costly, but also necessitates shutting-in the well, which means lost production. Similarly, use of a downhole heater for raising the temperature of the produced fluid requires a workover and dedicated power at the well site.
A relatively low-cost method described in the literature involves placement of gelled oil in the annulus as a means for achieving thermal insulation and preventing reflux. This is feasible only when a sliding sleeve door has been provided as a part of the well hardware/production tubing. Other limitations of the method are the formulation of an appropriate gelled fluid for the well conditions and the safety hazards involved in handling inflammable hydrocarbon fluids.
Some related prior art document are given here for reference:
U.S. Pat. No. 4,328,865 disclosed a system for controlling wax formation in oil wells using a thermal syphon wherein a confined annular space between the production tube and the oil string casing is provided by means of a plug, or “packer”, installed at a point well below the level at which solid waxes begin to deposit out of the exiting crude oil and a plug, or “packer”, installed above the point at which waxes would otherwise stop depositing out of the exiting crude oil and thereafter filling the confined annulus with a fluid working medium. The quantity and properties of the fluid working medium are arranged such that the medium is vaporized at the lower extremeties of the confined annulus and condensed on the surfaces of the upper regions of the confined annulus, particularly in the zone of wax deposition. The condensation process warms the production tube sufficiently to prevent formation of adhesive wax deposits or, alternatively, reliquifies a thin film of deposited wax which enables the flowing crude oil to remove the deposited wax. The condensed working medium flows by gravity to the lower part of the confined annulus where it again becomes available for vaporization and subsequent condensation. No external power is used for this circulation which is caused solely by temperature differences between lower and higher levels of the annulus.
There are some limitations of the approach described in above cited document: (a) Implementing the method will necessitate changing the well completion to a more complicated completion—a pair of packers, a capillary tube, a modified tubing hanger that allows the capillary to pass through it, etc. (b) Changing the well completion to install two packers requires a workover, hence involves costs/shutdowns/risks etc. (c) Providing the required amount of liquid/vapour between the packers and maintaining well control during workover is difficult (d) Liquids/vapours such as pentane are hazardous (e) the heat released during the condensation of liquid may not be sufficient to prevent wax deposition.
Some prior art literature document given here for reference:
“Annular packer fluids for paraffin control: model study and successful field application” J. D. Ashford, et. al; SPE Production Engineering, November 1990: This paper covers the evolution, full-scale model study, and field application of gelled packer fluids for paraffin control in naturally flowing wells. Field application of these insulating packer fluids has resulted in significant increases in the flowing tubing temperature in the seven wells treated to date. The temperature increases from gelled-packer-fluid application alone have eliminated paraffin problems previously controlled with repeated hot-oil treatments. Before this previously controlled with repeated hot-oil treatments. Before this application, chemical inhibition attempts were unsuccessful. The gelled fluid currently used is based on a phosphate ester and sodium aluminate reaction that produces an aluminium phosphate ester association polymer. The gellant is commonly used in oil-based fracturing fluids polymer. The gellant is commonly used in oil-based fracturing fluids.
“Wellbore refluxing in steam injection wells” G. P. Willhite, Journal of Petroleum Technology, March 1987”: This document provides that recent field experience has shown that the annulus does not dry out in insulated steam injection wells. Data were presented demonstrating the existence of refluxing in the wellbore which maintained the casing temperature at a constant value consistent with the annulus pressure. Casing temperatures under refluxing conditions were maintained at 212° F. when the annulus pressure was 1 atm while the casing temperature in a dry annulus was expected to be about 130° F. Because of this, heat losses were higher than anticipated which offset some of the economic benefits of using an insulated tubing string.
“Control of paraffin deposition in production operations” G. G. McClaflin and D. L. Whitfill, Journal of Petroleum Technology, November 1984: This document provide that significant operating costs are incurred from treatments designed to remove waxy deposits from production tubing or squeeze treatments designed to inhibit wax deposition. The costs are further increased by formation damage and loss of production that may result from these treatments. Our studies show that paraffin deposition can be prevented or greatly retarded by using chemical surfactants known as dispersants. Two specific surfactants were selected that proved to be very effective paraffin dispersants. One is oil soluble and the other is water soluble. These dispersants can be continuously injected into the well or they can be added in larger quantities in a “batch treatment” at specific time intervals. The choice of whether to use batch or continuous treatment is governed by the type and number of wells requiring treatment.
Therefore, it is apparent from the documents as described herein above that the conventional methods and ones existing in the prior art provide various disadvantages which affect the production of the oil in oil wells having packers and are not cost effective. The present invention provides a cost effective method for preventing wax deposition in oil well having packers and this method is less time consuming and helps in increasing the production and reducing the labor work.